1. The Field of the Invention
The present invention relates to an apparatus for pumping multiphase fluids, as in oil field production, particularly to a multistage pump for providing a large pressure boost to high gas-fraction inlet streams. More specifically, the invention relates to a multi-screw pump having multiple stages, to provide better power efficiency than traditional twin-screw pumps for high-pressure boost operation at gas fractions up to 100% without seizing or loss of pressure boost.
2. Background of the Invention
Drilling for oil and gas is an expensive, high-risk business, even when the drilling is carried out in a proven field. Petroleum development and production must be sufficiently profitable over the long term to withstand a variety of economic uncertainties. Multiphase pumping is increasingly being used to aid in the production of wellhead fluids. Both surface and subsea installations of these pumps are increasing well production. Multiphase pumps are particularly helpful in producing remote fields and many companies are considering their use for producing remote pockets of oil and for producing deep water reservoirs from remote facilities located in shallower water. Such multiphase pumps allow producers to transport multiphase fluids (oil, water, and gas) from the wellheads to remote processing facilities (instead of building new processing facilities near the wellheads and often in deep water). These multiphase pumps also allow fluid recovery at lower final reservoir pressures before abandoning production. Consequently, there is a greater total recovery from the reservoir.
For deep water reservoirs, producers are very interested in using multiphase pumps to transport wellhead fluids from deep water wellheads to remote processing facilities located in shallower water. While there are a number of technical difficulties in this type of production, the cost savings are very large. Building processing facilities over reservoirs in waters of 6,000 to 10,000 feet deep costs tens of billions of dollars, as compared to a cost of hundreds of millions of dollars to build similar facilities in moderate water depths of 400 to 600 feet. Consequently, producers would like to transport wellhead fluids from the sea-floor in deep waters through pipelines to remote processing facilities in moderate water depths.
Currently transport distances of 30 to 60 miles are being considered. In many locations around the world, a 30 to 60 mile reach from the edge of the continental shelf into deeper waters significantly increases the number of oil reservoirs which could be produced. In the Gulf of Mexico, for example, such a reach from water depths of 600 feet typically goes to water depths of 6,000 feet and deeper. In the near future, greater reaches up to 100 miles are envisioned. Multiphase pumps are a design being considered for supplying the pressure boost required for this long distance transport of wellhead fluids. The multiphase pumps typically have one end connected to a Christmas tree manifold, whose casing head is attached to the wellheads from which fluids flow as a result of indigenous reservoir energy, and the other end of the pumps are connected to a pipeline which transports the fluids from the wellhead to the remote processing site.
Wellhead fluids can exhibit a wide range of chemical and physical properties. These wellhead fluid properties can differ from zone to zone within a given field and can change with time over the course of the life of a well. Furthermore, well bore flow exhibits a well-known array of flow regimes, including slug flow, bubble flow, stratified flow, and annular mist, depending on flow velocity, geometry, and the aforementioned fluid properties. Consequently, the ideal multiphase pump should allow for a broad range of input and output parameters without unduly compromising pumping efficiency and service life.
Pumping gas-entrained liquids of varying gas content presents a difficult design problem. Some of these pumps have included: twin-screw pumps; helico-axial pumps; counter-rotating pumps; piston pumps; and diaphragm pumps. Twin-screw pumps are one of the favored types of pumps for handling the wide range of liquid/gas ratios found in wellhead fluids. Nevertheless, this type of pump has its detractions. For example, two well-known problems for twin-screw pumps are seizing and low efficiency.
A twin-screw pump has two rotors that rotate in a close fitting casing (rotor enclosure). For a given inlet volumetric rate, gas fraction increases result in mass rate reduction, decreases in the thermal transport capacity of the pumped fluids, and temperature elevations in the pump. At very high gas fractions and high pressure boosts the pump can lose its rotor-rotor or rotor-housing seals and the flow through the pump can stall; this leads to further temperature elevation in the pump. Consequently, at high pressure boosts, for a given set of operating conditions, a critical gas fraction exists. Pumping at gas fractions greater than the critical gas fraction will result in excessive heating of the pump rotors causing an expansion of the rotors such that the rotors may interfere with the pump body (rotor enclosure) causing the pump to seize.
In typical oil field applications, the gas fraction (or percentage of gas content of the wellhead fluid by volume at inlet conditions) is required to be less than some upper limit for a given pump pressure boost. This limit is typically 95% or greater gas fraction for pressure boosts of around 900 psi. In order to ensure that wellhead fluids do not exceed this requirement, several approaches have been taken including: (1) buffer tanks have been added upstream of the pump to dampen excessive gas/liquid ratio variations; (2) liquids from the pump outlet, or other liquids, are commingled with inlet stream fluids to reduce the inlet gas fraction; or (3) combinations of (1) and (2) are used to reduce the inlet gas fraction. Method (1) extends the operational range of the pump marginally and methods (2) and (3) extend the operating range a little more, but they are extremely inefficient. Even with these approaches, used either singly or in combination, pump seizing may still occur.
A more power efficient twin-screw pump would have several advantages over traditional twin-screw pumps. These advantages include: (1) reduced likelihood of seizing since less heat is generated within the pumping chamber; (2) reduced requirement for recirculation systems, which further reduce the efficiency and consequently generate more heat which must be removed from the pumping chamber in order to prevent seizing; (3) reduced drive requirements (for example, electric motors), thus reducing initial capital investment and providing a smaller and less massive system; (4) reduced power transmission capacity requirements (for example, a fifty-mile subsea electrical power transmission system used with a common pump size costs millions of dollars and typically has transformers, special variable frequency drives, and other special equipment for long distance transmissions), thus reducing initial capital investments; (5) lower operating costs (for less power, typically pumps of several megawatt size are considered); (6) lower maintenance and servicing costs (this is due to a longer lifetime at lower power loads and reducing servicing costs due to reduced weight of the drive--recovering a subsea pump for servicing or replacement is very expensive and the required vessel size and time for this operation are dependent on the size and weight of the pump/drive system); and (7) an economical system in situations where a standard twin-screw pump system costs more than the value received for the recovered fluids by using it.
Therefore, there is a need for a power efficient twin-screw pump capable of providing a large pressure boost to high gas-fraction inlet streams without seizing or loss of pressure boost. The present invention constitutes an improvement over my U.S. Pat. No. 5,779,451 issued Jul. 14, 1998.